Systems and processes for performing artificial lift on a well

ABSTRACT

Systems and processes for performing artificial lift on a well are disclosed. The systems and processes include tailoring a flow rate of a liquid and gas mixture based on one or more identified parameters that include well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.

CROSS-REFERENCE TO RELATED APPLICATIONS

This application claims priority to U.S. Provisional Application No. 62/656,794, filed Apr. 12, 2018, and entitled Liquid Assisted Gas-Lift, the entire contents of which is incorporated by reference herein.

FIELD OF THE INVENTION

Systems and processes for performing artificial lift on a well are provided.

BACKGROUND OF THE INVENTION

Conventionally, various artificial lift methods have been used to facilitate the extraction of an oil and/or a gas from a well. Certain conventional artificial lift methods include a gas lift method that relies on the injection of a gas into the well. However, such conventional gas lift methods are inefficient and resource intensive. For instance, in such conventional gas lift methods, the pressure of the source gas may limit the depth that the gas can be injected into the well, which can limit the ability of such a method to facilitate extraction. It would be desirable to develop artificial lift systems and processes that are more efficient, less resource intensive, and that can maximize production of the well.

BRIEF DESCRIPTION OF THE DRAWING

FIG. 1A is a top and side perspective view of an example artificial lift system, in accordance with aspects described herein.

FIG. 1B is a side view of the example artificial lift system of FIG. 1A, in accordance with aspects described herein.

FIG. 2 is a top and side perspective view of the frame assembly and side member supports of the example artificial lift system of FIG. 1A, in accordance with aspects described herein.

FIG. 3 is a top and side perspective view of the example artificial lift system of FIG. 1A with the outer housing removed, in accordance with aspects described herein.

FIG. 4 is a top and side perspective view of the example artificial lift system of FIG. 2, in the absence of the frame assembly and side member supports to show the liquid conduit, the gas conduit, the chemical additives source, the liquid pump, in addition to other components, in accordance with aspects described herein.

FIG. 5 is a diagrammatic depiction of the relative position of a liquid conduit, a gas conduit, a liquid pump, a chemical additives source, and additional components for use in an artificial lift system, in accordance with aspects described herein.

FIG. 6 depicts an example artificial lift system adjacent to a well, where the liquid inlet of the artificial lift system is in fluid communication with the interior of the production tubing of the well, and where the outlet of the artificial lift system is in fluid communication with the annulus of the well, in accordance with aspects described herein.

FIG. 7 is a block diagram of an example system that includes an injection optimizer, in accordance with aspects described herein.

FIG. 8 is a block diagram of an example computing environment suitable to implement aspects described herein.

FIG. 9 is a flow diagram illustrating one method for providing artificial lift to a well, in accordance with aspects described herein.

FIG. 10 is a flow diagram illustrating another method for providing artificial lift to a well, in accordance with aspects described herein.

FIGS. 11-13 depict schematic representations of a pressure gradient chart showing the pressure of the liquid gradient in the tubing using the systems and processes described herein compared to a gas lift process.

FIG. 14A is a schematic depiction of a test well configuration utilized in Example 2 herein.

FIG. 14B is a schematic diagram of a simulation model utilized in Example 2 herein.

FIG. 15 is a comparison between experimental data and simulation results for maximum injection pressure as a function of water flow rate for different gas injection rates described in Example 2.

FIG. 16 is a schematic representation of the gas/liquid profile in the annulus and tubing at different simulation times or stages as described in Example 2.

FIGS. 17A-17C depict the results of an unloading simulation described in Example 2.

FIGS. 18A-18C depict the results of another unloading simulation described in Example 2.

FIGS. 19A-19C depict the results of yet another unloading simulation described in Example 2.

FIG. 20 is a flow diagram illustrating one method for unloading a well, in accordance with aspects described herein.

DETAILED DESCRIPTION OF THE INVENTION Overview

In various aspects, systems and processes for producing artificial lift in a well are provided. In aspects, the systems and processes described herein can utilize a mixture of a liquid and a gas for injecting into the well. In such aspects, the flow rate of the liquid, the gas or the liquid and gas mixture and/or the compositional parameters of the mixture can be tailored based on identifying one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.

As noted above, certain conventional artificial lift systems, such as an artificial gas lift system, can be resource intensive and/or may be limited in its ability to effectively facilitate extraction or well production. For instance, as discussed above, the pressure of the source gas may limit the depth that the gas can be injected into the well. Certain conventional systems attempt to mitigate this limitation by utilizing multiple unloading valves in the well to enable a low surface injection pressure to kick-off gas lift by carefully setting the valve at a depth where there is sufficient gas pressure to allow injection through the valve. In such conventional systems, multiple unloading valves are used to kick-off gas lift by moving stepwise down the well from the top valve to the desired valve. However, installing and utilizing multiple unloading valves is not only resource intensive, it also provides multiple possible leak points in the tubing, which can decrease the reliability of the tubing. Further, certain conventional systems may provide additional energy or other resources to increase the pressure of a gas source for use in a conventional artificial gas lift system.

The systems and processes4 disclosed herein can alleviate one or more of these issues. For example, in certain aspects as described herein, it has been unexpectedly discovered that by injecting a mixture of a liquid and a gas with the compositional parameters described herein into the well, a deep-set valve is sufficient for effecting artificial lift in the well, which can eliminate the need to kick-off production using multiple valves as with conventional gas lift systems. In various aspects, the systems and methods described herein can eliminate a gas lift tubing valve altogether, as the systems and processes described herein can efficiently deliver the mixture to the bottom of the production tubing. In aspects, this reduction in the number of valves in the tubing not only conserves resources, but also may reduce the number of potential leak points in the tubing, which increases reliability in the well tubing.

Further as discussed above, the flow rate of the liquid and gas mixture and/or the compositional parameters of the mixture can be tailored based on identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. In such aspects, the artificial lift process can be tailored for specific well parameters and/or for specific identified production parameters, which can enhance production from the well and provide an efficient use of resources.

Accordingly, in one aspect an artificial lift system is provided. The artificial lift system can include a first mixer and a gas conduit. The gas conduit can extend between a gas intake at a first gas conduit end and the first mixer at a second gas conduit end. The artificial lift system can also include a liquid conduit. The liquid conduit can extend between a liquid intake at a first liquid conduit end and the first mixer at a second liquid conduit end. The artificial lift system can also include a liquid pump. The liquid pump can be in fluid communication with the liquid conduit at a pump connection point between the first liquid intake and the first mixer. The artificial lift system can also include a frame assembly, the frame assembly including a base member. Each of the first mixer, the gas conduit, the liquid conduit, and the liquid pump can be coupled to the base member. The artificial lift system can also include an outlet in fluid communication with the first mixer and adapted to output a first liquid and gas mixture into a well. The artificial lift system can also include a computing device having at least one processor and computer-readable instructions stored thereon. The computer-readable instructions, when executed by the at least one processor can cause the computing device to: identify one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, generate a first flow rate of the first liquid and gas mixture from the outlet and into the well.

In another aspect, an artificial lift system is provided. The artificial lift system can include a first mixer in fluid communication with an outlet; and a gas conduit. The gas conduit can extend between a gas intake at a first gas conduit end and the first mixer at a second gas conduit end. The artificial lift system can also include a liquid conduit, the liquid conduit extending between a liquid intake at a first liquid conduit end and the first mixer at a second liquid conduit end. The artificial lift system can also include a liquid pump, the liquid pump in fluid communication with the liquid conduit at a pump connection point between the first liquid intake and the first mixer. The artificial lift system can also include a chemical additive source, the chemical additive source coupled to a second mixer. The second mixer can be in fluid communication with the chemical additive source at a chemical additive connection point that is positioned between the pump connection point and the outlet. The artificial lift system can also include a frame assembly, the frame assembly including a base member, where each of the first mixer, the gas conduit, the liquid conduit, the liquid pump, the chemical additive source, and the second mixer are coupled to the base member.

In yet another aspect, a computing device is provided. The computing device can have at least one processor and computer-readable instructions stored thereon. The computer-readable instructions, when executed by the at least one processor can cause the computing device to: identify one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, determine a first flow rate of a liquid, a gas, or a liquid and gas mixture, for injecting into a well.

In another aspect, one or more nontransitory computer storage media is provided. The nontransitory computer readable media can store computer-useable instructions that, when used by one or more computing devices, cause the one or more computing devices to perform operations including: identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, determining a first flow rate of a liquid, a gas, or a liquid and gas mixture, for injecting into a well.

In yet another aspect, a computing device is provided. The computing device can have at least one processor and computer-readable instructions stored thereon. The computer-readable instructions, when executed by the at least one processor can cause the computing device to: identify, at a first time, one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, where the identifying at the first time comprises identifying a first pressure of the liquid and gas mixture in a mixture conduit of an artificial lift system, a first outlet pressure of the artificial lift system, or a first combination thereof; based on the identifying at the first time, determine a first flow rate of a liquid in a liquid and gas mixture, for injecting into a well; identify, at a second time, one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, where the identifying at the second time comprises identifying a second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, a second outlet pressure of the artificial lift system, or a second combination thereof; determine that the second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, a second outlet pressure of the artificial lift system, or a second combination thereof is less than the first pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the first outlet pressure of the artificial lift system, or the first combination thereof, respectively; and determine a second flow rate of the liquid, wherein the second flow rate of the liquid is decreased relative to the first flow rate of the liquid, and wherein the second flow rate of the liquid is determined based on the determining that the second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the second outlet pressure of the artificial lift system, or the second combination thereof is less than the first pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the first outlet pressure of the artificial lift system, or the first combination thereof, respectively.

In another aspect, one or more nontransitory computer storage media is provided. The nontransitory computer readable media can store computer-useable instructions that, when used by one or more computing devices, cause the one or more computing devices to perform operations including: identifying, at a first time, one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, where the identifying at the first time comprises identifying a first pressure of the liquid and gas mixture in a mixture conduit of an artificial lift system, a first outlet pressure of the artificial lift system, or a first combination thereof; based on the identifying at the first time, determining a first flow rate of a liquid in a liquid and gas mixture, for injecting into a well; identifying, at a second time, one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, where the identifying at the second time comprises identifying a second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, a second outlet pressure of the artificial lift system, or a second combination thereof; determining that the second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, a second outlet pressure of the artificial lift system, or a second combination thereof is less than the first pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the first outlet pressure of the artificial lift system, or the first combination thereof, respectively; and determining a second flow rate of the liquid, wherein the second flow rate of the liquid is decreased relative to the first flow rate of the liquid, and wherein the second flow rate of the liquid is determined based on the determining that the second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the second outlet pressure of the artificial lift system, or the second combination thereof is less than the first pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the first outlet pressure of the artificial lift system, or the first combination thereof, respectively.

Artificial Lift Processes and Systems: Liquid and Gas Mixture Parameters

As discussed above in one or more aspects, the artificial lift systems and processes described herein can utilize a mixture of a liquid and a gas for injecting into the well. Without being bound by any particular theory, in certain aspects it is believed that the weight of the liquid in the mixture can carry the gas further down the well, compared to conventional gas lift gas injection, and can provide for a deep-set injection into the tubing thereby facilitating artificial lift. In such aspects, the relative amounts of the liquid and/or gas can be tailored in the mixture to facilitate an effective artificial lift process. For example, if too little liquid is present in the mixture, then there may be insufficient hydrostatic pressure to allow gas to be circulated to the tubing injection point, Further, in certain aspects, if an overabundance of liquid is present in the mixture, the time required to unload the liquid and kick-off gas lift in the well significantly increases. In addition, in various aspects, the liquid injection rate can be tailored to create sufficient mixture velocity to carry gas bubbles downward to a deep-set valve.

In aspects, the liquid can include water, hydrocarbons, or a combination thereof. In aspects, the hydrocarbons can include crude oil. In the same or alternative aspects, the liquid can include a crude oil produced from the well where the artificial lift process is occurring. In a preferred aspect, the liquid includes crude oil.

In certain aspects, the gas can include hydrocarbons, air, or a combination thereof. In various aspects, the gas can include methane, ethane, propane, butane, air, or a combination thereof. In a preferred aspect, the gas includes methane.

In certain aspects, the gas can be present in the mixture in an amount of from 10% volume of the mixture to 99% volume of the mixture, 30% volume of the mixture to 95% volume of the mixture, 40% volume of the mixture to 85% volume of the mixture. In such aspects, the volume of the gas in the mixture refers to the mole fraction volume as determined at standard temperature and pressure.

In aspects, one or more chemical additives can optionally be added to the liquid and gas mixture for one or more purposes. For instance in one aspect, the chemical additives can include surfactants, de-emulsifiers, emulsifiers, drag reducing agents, or other chemical additives known to have an impact on multiphase flow and the pattern of flow, such as impacting the transition from one flow pattern to another. In the same or alternative aspects, the chemical additives can include chemical additives that are known to reduce the required surface injection pressures, to reduce the amount of fluid co-injected with the gas in the downward annular injection flow. In various aspects, the chemical additives can include chemical additives that are known to alter the flow in the production string downstream of the gas lift injection point and to alter the flow in a horizontal and near-horizontal sections of pipe such as the horizontal well. In the same or alternative aspects, the chemical additives can include scale inhibitors and/or corrosion inhibitors. In aspects, the chemical additives can include chemicals additives that are different than the liquid being utilized the liquid and gas mixture.

Artificial Lift Processes and Systems: Determining the Liquid and Gas Mixture and/or the Flow Rate

As discussed above, in certain aspects, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be tailored to facilitate effective artificial lift. Additionally or alternatively, in certain aspects, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be tailored based on identifying one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. Certain well geometry parameters, well productivity parameters, produced fluids properties, and surface production parameters are described in: Brill, J. P., & Mukherjee, H. K. (1999) Multiphase Flow in Wells, Society of Petroleum Engineers, SPE Monograph Series Vol. 17, ISBN: 978-1-55563-080-5, the entirety of which is incorporated by reference herein; and in Shoham, O. (2006) Mechanistic Modeling of Gas-Liquid Two-Phase Flow in Pipes, Society of Petroleum Engineers, ISBN 978-1-55563-107-9, the entirety of which is incorporated by reference herein.

In various aspects, the well geometry parameters can include any physical parameters of the well, or associated tubing, casings, or the like found in conventional oil wells. In certain aspects, a non-limiting list of well geometry parameters includes: an internal diameter of well tubing, an external diameter of well tubing, an internal diameter of a casing string, a depth of the casing string, an inclination of the casing string, a diameter of the vertical wellbore section, depth of the vertical section, depth of the injection valve, or a combination thereof.

In aspects, the produced fluids properties can include any properties or parameters associated with the fluids produced or extracted from the well. In certain aspects, a non-limiting list of the produced fluids properties includes: a density of the well-produced fluids, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, a viscosity of the well-produced fluids, a pressure of the well-produced fluids, a volume of the well-produced fluids, a temperature of the well-produced fluids, or a combination thereof.

In various aspects, the well productivity parameters can include parameters and/or properties associated with the productivity of the well. In certain aspects, a non-limiting list of the well productivity parameters includes an average reservoir pressure, a flow potential for the well, recent production rates from the well, such as 30 day average of an oil or condensate rate (barrels per day), a 30 day average water rate (barrels per day), a 30 day average gas rate (thousand standard cubic feet per day-mscf/D), a flowing tubing pressure, a well head pressure, a choke setting, a well head flowing temperature, or a combination thereof.

In aspects, the surface production parameters can include properties and/or parameters associated with the gas source, the liquid source, or the mixture of the liquid and gas being injected into the well or to be injected into the well. In the same or alternative aspects, the surface production parameters can include well head or casing head properties. In certain aspects, a non-limiting list of the surface production parameters includes: a gas conduit pressure, a liquid conduit pressure, an injection point pressure, a liquid and gas mixture conduit pressure, an outlet pressure, a well head shut-in pressure, a well head shut-in temperature, a production line pressure, a separator pressure, a casing head shut-in temperature, a casing head shut-in pressure, the gas volume available or extractable from the gas source, source gas pressure, or a combination thereof.

In aspects, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be tailored based on identifying one or more of: a diameter of the vertical wellbore section, depth of the vertical section, the gas volume available or extractable from the gas source, source gas pressure, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, oil or condensate average rate (barrels per day), a water average rate (barrels per day), a gas average rate (thousand standard cubic feet per day-mscf/D), or a flowing tubing pressure.

In certain aspects, the liquid and/or gas injection or flow rates sufficient to facilitate downward bubble flow in the well can be determined based on one or more of the properties discussed above, e.g., the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. As discussed further below, in various aspects, the downward bubble flow in the well can be facilitated to occur in the tubing casing annulus of the well. As discussed further below with reference to FIG. 6, the tubing casing annulus is the region in the borehole surrounding the tubing. In an alternative aspect, as discussed further below downward bubble flow in the well can be facilitated to occur in the tubing of the well.

In various aspects, optimizing the liquid and/or gas flow rates may employ the determination of various properties associated with the well or the artificial lift system and/or may employ specific control methods of the artificial lift system and processes disclosed herein. For instance, in certain aspects, one or more of the following may be performed to aid in tailoring the flow rate of the liquid and the gas to achieve artificial lift and/or maintain artificial lift: calculating the flow rate sufficient to facilitate downward bubble flow in the tubing casing annulus: calculating the minimum liquid weight required to achieve circulation of gas into the tubing in light of the source gas pressure; calculating the (gas) bubble rise velocity at multiple points in the tubing casing annulus; calculating the fluid levels in the casing or tubing in order to assign various flow regimes; tailoring the flow of the liquid and/or the gas to provide various patterns of high and/or low liquid injection rates. The determination of one or more of these parameters is further discussed below.

A multiphase flow correlation and/or model can be used for downward multiphase flow, such as, but not limited to, the Beggs & Brill correlation shown in equation (1) below. In such aspects, this correlation can aid in determining the liquid and gas injection rates at the surface required to achieve downward bubble flow in the tubing-casing annulus. In such aspects, a minimum liquid velocity must be achieved for injected gas lift gas to move downward can be determined.

F_(DRAG)≥F_(BUOYANCY)   (1)

In aspects, where chemical additives, such as the chemical additives discussed above are utilized, a homogeneous flow model may be utilized to identify both frictional and gravitational pressure changes in the annulus of the well with the formulas of equations (2), (3), (4), and (5) shown below. This flow model may be utilized to aid in determining the liquid and gas injection rates at the surface required to achieve downward bubble flow in the tubing-casing annulus.

$\begin{matrix} {\left( \frac{dP}{dx} \right)_{Gravitational} = {\rho_{m}\frac{g}{g_{c}}\sin \; \theta}} & (2) \\ {\left( \frac{dP}{dx} \right)_{Fractional} = \frac{f_{m}\rho_{m}v_{m}^{2}}{2\; g_{c}d}} & (3) \\ {\rho_{m} = {{\rho_{L}\lambda_{L}} + {\rho_{G}\left( {1 - \lambda_{L}} \right)}}} & (4) \\ {\lambda_{L} = \frac{Q_{L}}{Q_{L} + Q_{G}}} & (5) \end{matrix}$

Q_(L) is the liquid volumetric flow rate at in-situ conditions, Q_(G) is the gas volumetric flow rate at in-situ conditions, g is the acceleration of gravity, g_(c) is the gravitation constant and θ is the inclination of the pipe, f_(m) is the mixture friction factor, v_(m) is the velocity of the two-phase mixture at in-situ conditions, d is the diameter of the pipe, λ_(L) is the no-slip liquid holdup, ρ_(L) is in-situ liquid density, ρ_(G) is the in-situ gas density and ρ_(m) is the in-situ mixture density. In aspects, in-situ conditions refers to conditions during operation of the processes disclosed herein.

In one or more aspects as discussed above, the fluid level in the casing/tubing can be determined and one or more flow regimes can be assigned for use. In such aspects, flow modeling can be done for the various regimes of the pipe which may be present in the well at startup which may be assigned single-phase gas, single-phase liquid, and multiphase (e.g., gas and liquid) designations. This may be done by comparing shut-in wellhead pressures with estimated reservoir pressure, for instance as with equation (6) below.

P _(CHSI) =P _(res)−ρ _(L) ┌D _(bh) −D _(LL)┐−ρ _(C) ┌D _(LL)┐  (6)

P_(CHSI) is the Casing-Head Shut-In Pressure, P_(res) is the average reservoir pressure or an approximation of the buttonhole pressure at shut-in conditions just prior to starting the artificial lift procedure, ρ_(L) is liquid density, ρ_(G) is gas density and D_(bh) is the Total Vertical Depth to the reservoir perforations or intake point, and D_(LL) is the depth to the liquid level in the tubing-casing annulus.

In one or more aspects, utilizing one or more of the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, one can determine the gas bubble rise velocity at one or more points in the tubing-casing annulus to ensure that the gas will move downward in the tubing-casing annulus to a deep-set valve. In such aspects, the gas bubble rise velocities can be utilized to determine flow or injection rates of the liquid and gas mixture to create suitable conditions for downward movement of the gas.

In aspects, based on one or more of the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, one can identify flow patterns for the liquid, gas, or mixture thereof in order to create a specific environment in the tubing-casing annulus for downward movement of the injected gas such that the bubble rise velocity is exceeded by the downward velocity of the liquid and gas mixture. In other words, the relative amounts of gas and liquid injected are important to establish the proper downward multiphase flow pattern to both create the proper hydrostatic, or weight, and achieve a velocity and flow pattern for downward flow of the gas-liquid mixture.

Above, various determinations are described that generally may be associated with the tailoring of the liquid and/or gas flow rate to achieve downward movement of the gas and, e.g., into the production tubing. In various aspects, one or more of the tubing head pressure, tubing head temperature, casing head pressure, or casing head temperature may be monitored in order to modify the injected gas and liquid rates to ensure the gas is circulated through the deep-set valve or around the bottom of the tubing if no valve is used. In such aspects, if casing head pressures increase beyond an expected threshold, additional liquid can be injected to add additional “weight” to keep below the maximum gas source pressure. Further, in such aspects, iterations may be performed between the injection flow pattern calculations and the integrated “weight” history injected during the kick-off process.

In certain aspects as discussed above, it may be desirable to minimize the use of the liquid being injected into the well. For instance, in certain aspects, the liquid injection rate may be initially high in order to facilitate the downward movement of the gas; however, once the gas enters the production tubing, it may be desirable to reduce the injection rate of the liquid. In aspects, prior to changing the liquid flow rate, gas entry into the tubing may be detected through monitoring one or more parameters, such as the tubing head pressure and temperature. For instance, an increase in flowing tubing head pressure may indicate a drop in density of fluids in the tubing string caused by the entry of gas. In the same or alternative aspects, the multiphase flow calculations and the monitoring of the casing head pressure may be utilized to detect or determine gas entry into the tubing. For example, a decrease in injection casing head pressure may indicate a drop in density of fluids in the tubing string caused by the entry of gas, multiphase flow velocities can be utilized to determine the time when gas reaches the valve or end-of-tubing if no valve is used, and/or multiphase flow correlations can be utilized to determine the pressure at the injection point by calculating upward flow in the tubing utilizing the measured wellhead tubing flowing pressure.

In aspects, once the gas enters the tubing, a ramping down or adjustment of the liquid injection rate may be pursued. In such aspects, the reduction in liquid injection rates or ramping down can be performed in part by monitoring both the wellhead tubing and casing pressures so that the appropriate parameters are present to maintain gas entry in the production tubing. Further in such aspects, a non-limiting list of various methods for ramping down the liquid injection rate while maintaining the gas entry into the tubing includes: iterating the weight of the fluid column with the wellhead tubing and casing pressures to maintain injection at the downhole injection point; utilizing multiphase flow correlations to predict the pressure at the gas injection point in the tubing (either at the single deep-set valve or at the end of the tubing) and iterating this the downward flow calculation to match the input flowing tubing head pressure and casing head injection pressure; or switching the liquid rates from high to low levels to create slugs of single-phase liquid, bubble or slug/churn flow that travel downward separated by gas bubbles.

Artificial Lift Processes and Systems: Example Systems

FIGS. 1A-4 depict one example system 100 for providing artificial lift in a well. It should be understood that the system 100 depicted in FIGS. 1A-4 is just one example system for providing artificial lift and that other systems and configurations of the components are contemplated by the disclosure herein. Starting with FIGS. 1A and 1B, the exterior portion of housing 110 and a portion of the frame assembly 120 for this example system is depicted. As best seen in FIG. 1B, in aspects, the system 100 can also include one or more of a power distribution system 130, a variable frequency drive 140, and a computing device 150. The power distribution system 130, the variable frequency drive 140, and the computing device 150 will be discussed further below.

In certain aspects, the system 100 can be mobile and is capable of being transported to and from a well, and/or transported from one well to another well. In aspects, the system 100 is sized to fit on a flatbed trailer of an 18-wheel tractor trailer. In such aspects, the system 100 can have a length l, as identified in FIG. 1A, of from 1.5 meters (m) to 24 m; 2.4 m to 21 m, or 3 m to 17 m. In the same or alternative aspects, the system 100 can have a width w, as identified in FIG. 1A, of from 0.3 m to 6 m; 0.6 m to 4.5 m, or 0.9 m to 3.7 m. In various aspects, the system 100 can have a height h, as identified in FIG. 1A, of from 0.3 m to 6 m; 0.6 m to 4.5 m, or 0.9 m to 3.7 m. In certain aspects, the system 100 has a mass of from 700 kilograms (kg) to 50,000 kg, from 900 kg to 30,000 kg, or from 1100 kg to 15,000 kg.

In aspects, as discussed above, the system 100 can be transported from one location to another location. In such aspects, the frame assembly 120 can be adapted to transport the system 100 from one location to another. For example, as can be seen in FIGS. 1A and 1B, the frame assembly 120 can include voids 122 for engaging with a transport device, such as a forklift or crane. In aspects, the frame assembly 120 comprises a metal material that is capable of supporting and transporting the system 100 having a weight of from 700 kg to 50,000 kg, 900 kg to 30,000 kg, or 1100 kg to 15,000 kg. In one aspect, the system 100 can be configured for transport on a trailer.

FIG. 2 depicts the frame assembly 120 for the system 100. In the aspect depicted in FIG. 2, the frame assembly 120 includes a base member 124, a plurality of side support members 126 extending up from the base member 124, and a top support member 128. As discussed above, in aspects, the frame assembly 120 can include voids 122 that can be utilized to lift and/or move the system 100. In such aspects, the voids 122 may be defined the base member 124. It is understood that the voids 122 are just one example way that the frame assembly 120 is adapted to transport the system 100 from one location to another and that other modifications and/or additions to the frame assembly 120 that are capable of facilitating the transport of the system 100 are also contemplated by the disclosure herein.

FIG. 3 depicts the frame assembly 120 and additional components of the system 100 coupled to the frame assembly 120. In certain aspects, one or more of the additional components of the system 100 can be coupled to the base member 124. In aspects, as discussed further below, the one or more additional components that are coupled to the frame assembly 120 can include, but are not limited to, a gas conduit 160, a liquid conduit 170, a liquid pump 174, a first mixer 180, and an outlet 182. Additional components and associated connections are discussed further below with reference to FIG. 4.

As can be seen in the aspect depicted FIG. 3, at least the gas conduit 160, the liquid conduit 170, the liquid pump 174, and the first mixer 180 are coupled to the frame assembly 120 via the base member 124. In the same or alternative aspects, at least the gas conduit 160, the liquid conduit 170, the liquid pump 174, and the first mixer 180 are coupled to and are positioned within the frame assembly 120 such that at least the gas conduit 160, the liquid conduit 170, the liquid pump 174, and the first mixer 180 are positioned in an interior volume 111 of the housing, e.g., the housing 110 of FIG. 1A.

FIG. 4 depicts the additional components of the system 100 also illustrated in FIG. 3 but in the absence of the frame assembly 120. As can be seen in FIG. 4, the system 100 can include, but is not limited to, a gas conduit 160, a liquid conduit 170, a liquid pump 174, a first mixer 180, and an outlet 182.

In the aspect depicted in FIG. 4, the gas conduit 160 can extend between a gas intake 162 at a first gas conduit end 163 and a first mixer 180 at a second gas conduit end 165. In aspects, the gas conduit 160, via the gas intake 162, can be coupled a source gas. As discussed above, in various aspects, the source gas can include hydrocarbons, air, or a combination thereof. In various aspects, the gas can include methane, ethane, propane, butane, air, or a combination thereof. In a preferred aspect, the gas includes methane. In various aspects not depicted in the figures, a control valve can be placed between the gas supply and the gas intake. For example, the control valve may facilitate connection to a customer provided gas supply. In the same of alternative aspects not depicted in the figures, a choke valve can be placed between the gas supply and the gas intake 162 to control the gas flowing into the gas conduit 160 and the system 100. In such aspects, a computing device, e.g., the computing device 150 of FIG. 1B, may operate or direct the operation of such a choke valve.

In one or more aspects, the gas conduit 160, via the gas intake 162, may direct the gas communicated from the gas source through a gas flow meter 166 and a gas valve 167 to the first mixer 180. In aspects, the gas communicated from the gas source can be pressurized. In certain aspects, a gas pressure gauge sensor 168, a gas temperature gauge sensor 169, or both can be coupled to the gas conduit 160 at a position between the gas intake 162 and the first mixer 180. In various aspects, the gas pressure gauge sensor 168, the gas temperature gauge sensor 169, or both can be adapted to provide gas temperature and/or gas pressure information to a computing device, e.g., the computing device 150 of FIG. 1B, where such information can be utilized in the processes described herein.

In the aspect depicted in FIG. 4, the liquid conduit 170 can extend from the liquid intake 172 at a first end 173 to the first mixer 180 at a second end 175. As discussed above, the liquid can include water, hydrocarbons or a combination thereof. In one aspect, the hydrocarbons can include a crude oil. In the same or alternative aspects, the liquid can include a crude oil produced from the well where the artificial lift process is occurring.

In aspects, the liquid conduit 170 a may direct the liquid communicated from the liquid source to the liquid pump 174. In the aspect depicted in FIG. 4, a pressure gauge 176 may be positioned between the liquid intake 172 and the liquid pump 174 to measure the pressure of the liquid line upstream of the liquid pump 174. In such aspects, the liquid pump 174 may be configured to pump the liquid and/or the liquid and gas mixture through the liquid pump exit conduit 170 b and on through the remaining portion of the system components and out through the outlet 182 to a well. In an aspect not depicted in FIG. 4, a valve may be coupled to the outlet 182.

In aspects, the liquid pump 174 can include an electric motor. In such aspects, a variable frequency drive, e.g., the variable frequency drive 140 of FIG. 1B, may control the amount of power going into the electric motor of the liquid pump 174 in order to control the flow rate of the output liquid. In such aspects, a computing device, e.g., the computing device 150 of FIG. 1B, can operate or direct the operation of the variable frequency drive.

In aspects, a recirculation conduit 171 can optionally be included in order to aid in controlling the pressure in the liquid pump exit conduit 170 b. In such aspects, the use of the recirculation conduit 171 can allow for the control of the pressure and flow rate independent of one another. As can be seen in the aspect depicted in FIG. 4, a pump discharge pressure gauge 170 c may be coupled to the liquid pump exit conduit 170 b and adapted to monitor the pressure of the pump discharge in the liquid pump exit conduit 170 b. In aspects, a recirculation liquid control valve 179 can permit or block the recirculation of the liquid from the liquid pump exit conduit 170 b and through the recirculation conduit 171, which may be returned to a liquid source or a holding vessel. In aspects, a computing device, e.g., the computing device 150 of FIG. 1B, can operate or direct the operation of the recirculation liquid control valve 179.

In aspects, as discussed above, chemical additives can optionally be added to the liquid and gas mixture. For instance, in the aspect depicted in FIG. 4, a chemical additives source 192 can be coupled to a second mixer 184. Further, in the aspect depicted in FIG. 4, a chemical pump 190 can be coupled to the chemical additives source 192 to supply the chemical additives to the second mixer 184 and the liquid in the liquid conduit 170. In certain aspects, the chemical pump 190 can be driven by an electric motor. In such aspects, a variable frequency drive, e.g., the variable frequency drive 140 of FIG. 1B, may control the amount of power going into the electric motor of the chemical pump 190 in order to control the flow rate of the output liquid. In such aspects, a computing device, e.g., the computing device 150 of FIG. 1B, can operate or direct the operation of the variable frequency drive.

In aspects, the chemical additive source 192 can be a tank of one or more chemical additives that is housed within an interior volume of the system housing, e.g., the housing 110 of FIG. 1A. In alternative aspects not depicted in the figures, a chemical additives source can be exterior to the system and can be provided to the system via a chemical conduit. In various aspects, the chemical additives source 192 (and/or an exterior chemical additives source) can include a meter and valve for controlling the rate of chemical additives addition to the liquid in the liquid conduit or the mixture of the liquid and the gas.

In aspects, the chemical additives can include any conventional chemical additives utilized in well extraction processes. For instance in one aspect, the chemical additives can include surfactants, de-emulsifiers, emulsifiers, drag reducing agents, or other chemical additives known to have an impact on multiphase flow and the pattern of flow, such as impacting the transition from one flow pattern to another. In the same or alternative aspects, the chemical additives can include chemical additives that are known to reduce the required surface injection pressures, to reduce the amount of fluid co-injected with the gas in the downward annular injection flow. In various aspects, the chemical additives can include chemical additives that are known to alter the flow in the production string downstream of the gas lift injection point and to alter the flow in a horizontal and near-horizontal sections of pipe such as the horizontal well. In the same or alternative aspects, the chemical additives can include scale inhibitors and/or corrosion inhibitors. In aspects, the chemical additives can include chemicals additives that are different than the liquid being utilized the liquid and gas mixture.

In certain aspects, the liquid being pumped in the liquid conduit 170 can be transported to the first mixer 180 where the liquid (and optionally any chemical additive(s)) is mixed with the gas from the gas conduit 160 prior to being transported to the well via the outlet 182. In aspects, a liquid valve 183 may be placed upstream of the first mixer 180, e.g., between the liquid intake 172 and the first mixer 180, to control the flow rate of the liquid entering the first mixer 180 and/or exiting the outlet 182. In aspects, the liquid valve 183 may be used when disconnecting the system from the well. In aspects, a computing device, e.g., the computing device 150 of FIG. 1B, can operate or direct the operation of the liquid valve 183.

In aspects, the first mixer 180 can be configured to mix the liquid and the gas into a multiphase mixture, e.g., a mixture of the liquid and the gas. In one example aspect depicted in FIG. 4, the first mixer 180 can be a T-conduit fluidly coupled to the gas conduit 160 and the liquid conduit 170. The first mixer 180 can be any other type of convenient mixer for mixing a liquid and a gas, including but not limited to a Y-shaped conduit or sphere-shaped conduit. In the same or alternative aspects, the first mixer 180 can include one or more internal baffles in the conduit to facilitate efficient mixing of the liquid and the gas. In yet another aspect, the first mixer 180 may be configured to include a gas diffuser or sparger. It is appreciated that the second mixer 184 can include any or all of the properties and parameters of the first mixer 180 discussed herein.

In certain aspects, once the liquid and the gas is converted into the mixture of the liquid and the gas in the first mixer 180, the mixture can be transported via a mixture conduit 185 to the outlet 182 and ultimately to the well. In aspects, one or more temperature and/or pressure gauges, e.g., pressure gauge 187 may be positioned in the mixture conduit 185 for providing such information to a computing device, e.g., the computing device 150 of FIG. 1B.

FIG. 5 depicts another example of a configuration for use in the systems and processes disclosed herein. As can be seen in the aspect depicted in FIG. 5, a gas conduit 210 can be coupled to a gas source 220 via a gas intake 212. Further in the aspect depicted in FIG. 5, the gas conduit 210 can include a liquid meter 213 placed between needle valves 215. Additionally in aspects, the gas conduit 210 can include a gas flow control valve 214 between the gas source 220 and the first mixer 219. In various aspects, a check valve 216 can be positioned along the gas conduit 210 between the gas flow control valve 214 and the first mixer 219 in order to prevent backflow from the first mixer 219 into the gas conduit 210. In aspects, the gas source 220 can include one or more of the gases mentioned above for use in the artificial lift systems and processes disclosed herein. In various aspects one or more of the liquid meter 213, the gas flow control valve 214, or the check valve 216 can be in communication with a computing device, e.g., the computing device 150 of FIG. 1B. In such aspects, the computing device can operate or direct the operation of the gas flow control valve 214 in order to control or modulate the flow rate of the gas into the first mixer 219.

As can be seen in the aspect depicted in FIG. 5, a liquid conduit 260 can be coupled to a liquid source 230 via a liquid intake 232. In various aspects, the liquid source 230 can include any or all of the properties of the liquids and liquid source described above with reference to FIG. 4. The liquid conduit 260 can extend from the liquid intake 232 to a liquid pump 234 and on to the first mixer 219. In aspects, the liquid pump 232 can comprise an electric motor 229, which in turn may be controlled or operated by a computing device via a variable frequency drive, as discussed above with reference to FIG. 4. In aspects, a recirculation conduit 261 can optionally be included to aid in controlling the pressure in the portion 236 of the liquid conduit 260 adapted to receive the pumped liquid from the liquid pump 234. In such aspects, a recirculation liquid control valve 235 can permit or block the recirculation of the liquid from the portion 236 of the liquid conduit 260 and through the recirculation conduit 261, which may be returned to a holding vessel 231.

The liquid conduit 260 can include, in aspects, a liquid meter 238 and one or more valves, e.g., a needle valve 237a and a liquid flow control valve 237b, positioned between the liquid pump 234 and the first mixer 219. In the same or alternative aspects, the liquid conduit 260 can include a liquid check valve 239 to prevent backflow from the first mixer 219 into the liquid conduit 260.

As can be seen in the aspect depicted in FIG. 5, a chemical additives conduit 241 can be coupled to a chemical additives source 240 and operable to provide one or more chemical additives to a mixture of the liquid and the gas downstream of the first mixer 219 in the mixture conduit 291. In aspects, the chemical additives and the chemical additives source 240 can include any or all of the properties of the chemical additives and the chemical additives source discussed above with reference to FIG. 4.

In aspects, a chemical pump 242 can be coupled to the chemical additives conduit 241 in order to provide the flow of the chemical additives from the chemical additives source 240 to the second mixer 245, where the chemical additives can be incorporated into the mixture of the liquid and the gas. In aspects, a chemical additives needle valve 244 or other valve can be positioned along the chemical additives conduit 241 between the chemical pump 242 and the second mixer 245 to control the flow of chemical additives into the mixture conduit 291 and ultimately through an outlet 221 and into a well 250.

In the aspect depicted in FIG. 5, a skid 300, or base member of a frame assembly, can support the conduits and components depicted in the interior portion 301 of the skid 300. As depicted in FIG. 5, the chemical additives source 240, the gas source 220, the supplemental liquid source 231, and the liquid source 230 are external to the interior portion 301 of the skid 300.

As discussed above, in various aspects the systems and processes herein can utilize a computing device to identify various parameters, e.g., one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters discussed above, and tailor a flow rate of the liquid mixture and/or tailor the compositional makeup of the mixture by controlling the flow rate of the liquid and/or the gas. For instance, as noted above, such a computing device can identify various parameters, e.g., one nor more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters and operate or direct the operation of one or more of the valves or pumps discussed above in order to control the flow rate or flow of the gas, the liquid, the chemical additives, or a combination thereof.

As discussed above, in various aspects, the systems and processes disclosed herein can be utilized to provide artificial lift to a well, for example, by injecting a mixture of a gas and a liquid into a well. FIG. 6 depicts an example artificial lift system 400 coupled to a well 500. In various aspects, the artificial lift system 400 of FIG. 6 can include any or all of the parameters discussed above with respect to FIGS. 1A-5. It should be understood that while the well 500 depicted in FIG. 6 is generally a vertically oriented well, the systems and processes disclosed herein can also be utilized on horizontal wells. That is in certain aspects, the artificial lift systems disclosed herein can be coupled to a vertical or a horizontal well to effectuate artificial lift.

As can be seen in FIG. 6, the well 500 includes a borehole 502 that extends into the ground to a formation (not depicted in the figures). In the aspect depicted in FIG. 6, the borehole 502 includes a production tubing 510 extending through at least a portion of the borehole 502 and is adapted to permit production fluids, including but not limited to crude oil, to be extracted from the formation. Further, as can be seen in FIG. 6, there is a annulus 520 that is the space between the exterior 512 of the production tubing 510 and the surface 522 of the borehole 502.

In various aspects of the systems and processes described herein, the mixture of the liquid and the gas, can exit an outlet 420 of the artificial lift system 400 and be injected into the annulus 520 via a conduit 430. In such aspects, the mixture of the liquid and the gas may travel down the borehole 502 to a deep-set valve 530 coupled to the production tubing 510, where the liquid and/or the gas is transported into the production tubing 510 to facilitate artificial lift of the well, as indicated by the solid arrow extending down to the deep-set valve 530. In an aspect not depicted in the figures, as discussed above, there may not be a valve at or near the bottom of the production tubing and the systems described herein can provide the mixture to the bottom of the production tubing where such mixture can enter the production tubing, as indicated by the dashed arrow extending down the annulus 520 and into the production tubing 510.

It should be understood that while this one example operation depicted in FIG. 6 describes the gas, liquid, or mixture thereof being injected from the artificial lift system 400 and into the annulus 520 and ultimately into the production tubing 510 to facilitate extraction of production fluids by traveling through the production tubing 510 and out of the well 500, an alternative operation is also contemplated by the systems and processes described herein. For instance, in one aspect, the gas, liquid, or mixture thereof can be injected from the artificial lift system 400 and into the production tubing 510 and thereby travel downhole and enter the annulus 520 via a valve or bottom of the tubing to facilitate extraction of production fluids out and through the annulus 520.

As discussed above, in various aspects, the systems and processes disclosed herein can include utilizing a liquid that comprises hydrocarbons in the mixture of the liquid and the gas. In such aspects, the systems disclosed herein can utilize a production fluid, e.g., a crude oil from the well, as the liquid source or liquid for use as at least one component of the liquid in the mixture of a liquid and a gas for injecting into the well. FIG. 6 depicts one example arrangement where an artificial lift system, e.g., the artificial lift system 400, is adapted to receive a production fluid as a liquid source. As can be seen in FIG. 6, a conduit 412 is coupled to a liquid inlet 410 and extends into the production tubing 510 so that the production fluid, for example a crude oil, can be utilized in the systems and processes disclosed herein. While not depicted in FIG. 6, the production fluid may be exposed to one or more post-production systems or processes prior to transporting the crude oil or other fluid to the liquid inlet 410. A non-limiting list of post-production systems and processes includes the use of one or more separators to remove water, other liquids, and/or gas, and the use of a storage vessel from which the crude oil can be withdrawn.

In various aspects as discussed above, the flow rate of the mixture exiting the outlet 420 and being injected into the annulus 520 can be tailored based on identifying one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. In such aspects, a computing device 440 can identify and/or receive information on one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters to determine the flow rate of the mixture of the liquid and the gas. The flow rate of the mixture of the liquid and the gas can be adjusted as discussed above with reference to FIGS. 1A-5. In such aspects and not depicted in the figures, one or more flow meters, pressure gauges, and/or temperature gauges may be placed at any specific location in the production tubing 510, annulus 520, borehole 502, conduit 430, and/or conduit 412, and be adapted to transmit such information to the computing device 440 for use in tailoring the flow rate of the liquid and gas mixture.

FIG. 7 depicts a system 700 for use in implementing aspects described herein for optimizing the injection of the liquid and gas mixture into a well and/or for tailoring the flow rates of the liquid and the gas into the well. It should be understood that the system 700 is an example of one suitable computing system environment and is not intended to suggest any limitation as to the scope of use or functionality of aspects of the present invention. Neither should the system 700 of FIG. 7 be interpreted as having any dependency or requirement related to any single source module, service, or device illustrated therein.

Generally, the system 700 can include an injection optimizer 710 that can identify or receive a variety of inputs or information, such as one or more of well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, to tailor or optimize the relative amounts of the gas and liquid in the mixture being injected into a well and/or the flow rate of the mixture being injected into the well, e.g., to facilitate effective artificial lift. In aspects, the system 700 may include the injection optimizer 710, one or more sensors 720, one or more computing devices 740, one or more controllers 750, and optionally one or more data sources 760. In aspects, the injection optimizer 710, one or more sensors 720, one or more computing devices 740, one or more controllers 750, and one or more data sources 760 may be in communication with each other, through wired or wireless connections, and/or through a network 730. The network 730 may include, without limitation, one or more local area networks (LANs) and/or wide area networks (WANs). Such networking environments are commonplace in enterprise-wide computer networks, intranets, and the Internet. Accordingly, the network 730 is not further described.

In one or more aspects, the one or more sensors 720 can include any sensors that can identify or provide information related to one or more of the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters discussed above. In such aspects, the one or more sensors 720 can include any or all of the sensors, flow meters, pressure gauges, and temperature gauges utilized in an artificial lift system, including sensors associated with liquid and/or gas conduits and sensors in or near the well. In aspects, the one or more sensors 720 can include any or all of the sensors, flow meters, or gauges discussed above with reference to FIGS. 4 and 5 that are operable to measure flow rate, temperature, and/or pressure, of the liquid, gas, or mixture thereof. In the same or alternative aspects, the one or more sensors 720 can include one or more pressure and/or temperature sensors downhole, e.g., a pressure sensor operably coupled to a downhole injection valve, e.g., the deep-set valve 530 discuss above with reference to FIG. 6. In further aspects, the one or more sensors 720 can include one or more sensors associated with measuring various properties of the production fluid, tubing, casing head, or a combination thereof.

In certain aspects, the one or more data sources 760 can include any information associated with the well, source gas, source liquid, or produced fluids. For instance, in one aspect, the one or more data sources 760 can include information associated with the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. For instance in aspects, the one or more data sources 760 can include information associated with the well geometry, historical well production parameters, or produced fluid parameters. In one aspect, the one or more data sources 760 can include prior parameter information, while the one or more sensors 720 can include real-time or near real-time parameter information.

In aspects, the one or more controllers 750 can include any device capable of adjusting a valve, pump, motor associated with a valve or pump, or the like for controlling the flow or flow rate of a liquid, gas, or a mixture thereof. In aspects, the one or more controllers 750 can be associated with any of the flow control valves, electric motors, or pumps discussed above, such as the flow control valves, electric motors, or pumps described in the systems of FIGS. 4 and 5.

In various aspects, the injection optimizer 710 can include a receiver 712, a flow rate determiner 714, and an output communicator 716. In aspects, the receiver 712, the flow rate determiner 714, and the output communicator 716 may be implemented as one or more stand-alone applications. Further, various services and/or modules may be located on any number of servers. By way of example only, the injection optimizer 710 may reside on a server, cluster of servers, a cloud-computing device or distributed computing architecture, or a computing device remote from one or more of the data sources 760, the one or more computing devices 740, or the one or more controllers 750. In certain aspects, one or more services or modules of the injection optimizer 710 may reside in one or more of the one or more computing devices 740 associated with the artificial lift systems described herein. In the same or alternative aspects, one or more services and/or modules of the injection optimizer 710 may reside in one or more servers, cluster of servers, cloud-computing devices or distributed computing architecture, or a computing device remote from the one or more computing devices 740 associated with the artificial lift systems described herein.

In various aspects, the receiver 712 of the injection optimizer 710 can receive information from the one or more sensors 720 and/or the one or more data sources 760. In certain aspects, the information from the one or more sensors 720 and/or the one or more data sources 760 may be transmitted to and received by the receiver 712 via the network 730 and may include wired or wireless transmission of the information, including but not limited to a physical USB connection, an Ethernet connection, a Bluetooth connection, near-field communication, WiFi communication, wireless USB communication, optical communication, such as IrDA, a cellular network or a combination thereof. In aspects, the one or more computing devices 740 may transmit to the receiver 712 data from the one or more data sources 760 and/or the one or more sensors 720.

In aspects, once the injection optimizer 710 has received the information from the one or more sensors 720 and/or the one or more data sources 760, the flow rate determiner 714 utilizes that information to determine a flow rate of the liquid and/or the gas in the mixture, and/or utilizes that information to determine the relative amounts of the liquid and the gas in the mixture.

In one example, as discussed above, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be determined by the flow rate determiner 714 to facilitate effective artificial lift based on one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters received by the receiver 712. Additionally or alternatively, in an example aspect, the relative amounts of the gas and liquid in the mixture and/or the flow rate of the mixture can be tailored or optimized based on one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters received by the receiver 712.

In another example also discussed above, once the injection optimizer 710 has received the information, e.g., one or more of the well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, from the one or more sensors 720 and/or the one or more data sources 760, the flow rate determiner 714 can determine the liquid and/or gas injection or flow rates sufficient to facilitate downward bubble flow in the well.

In yet another example, the receiver 712 may receive information from a sensor of the one or more sensors 720 that senses the liquid pump discharge pressure and/or the unit discharge pressure is decreasing and the flow rate determiner 714 may determine that the flow rate of the liquid can begin to be tapered off, e.g., in an unloading process for a well.

It should be understood that the above examples are only a few scenarios to demonstrate the functionality of the flow rate determiner 714 and that any combination of other information from the one or more data sources 760 and/or the sensors 720 can be utilized to optimize the flow rates of the liquid and/or the gas in the mixture for injecting into the well, and/or to determine the compositional parameters of the liquid and the gas in the mixture.

In aspects, the output communicator 716 communicates to the one or more controllers 750 and/or the one or more computing devices 740 the determined flow rates for the liquid and/or the gas in the liquid and gas mixture. For instance in one aspect, the output communicator 716 can communicate with the one or more controllers 750 to adjust the flow rate of the liquid, the gas or the liquid and the gas. As noted above, the one or more controllers 750 can be associated with any of the flow control valves, electric motors, or pumps discussed above. In one aspect, the output communicator 716 can communicate the determined flow rates for the liquid and/or the gas in the liquid and gas mixture to the one or more computing devices 740, where the one or more computing devices 740, in turn, can directly or indirectly communicate the determined flow rates, or operations or instructions that achieve the determined flow rates, to components that control the one or more valves, electric motors, or pumps. For instance in one example, the one or more computing devices 740 can provide instructions to control the amount of power going to an electric motor that controls one or more of a liquid pump, a flow control valve, or a pump.

FIG. 8 depicts one example operating environment for a computing device in which aspects of the present disclosure may be implemented is described below in order to provide a general context for various aspects of the present disclosure. Referring to FIG. 8, an example operating environment for implementing aspects of the present disclosure is shown and designated generally as computing device 800. The computing device 800 is but one example of a suitable computing environment and is not intended to suggest any limitation as to the scope of use or functionality of aspects disclosed herein. Neither should the computing device 800 be interpreted as having any dependency or requirement relating to any one component nor any combination of components illustrated.

Aspects herein may be described in the general context of computer code or machine-useable instructions, including computer-useable or computer-executable instructions such as program modules, being executed by a computer or other machine, such as a personal computing device. Generally, program modules including routines, programs, objects, components, data structures, and the like, and/or refer to code that performs particular tasks or implements particular abstract data types. Aspects disclosed herein may be practiced in a variety of system configurations, including hand-held devices, consumer electronics, general-purpose computers, more specialty computing devices, and the like. Aspects disclosed herein may also be practiced in distributed computing environments where tasks are performed by remote-processing devices that are linked through a communications network.

With continued reference to FIG. 8, the computing device 800 includes a bus 810 that directly or indirectly couples the following devices: a memory 812, one or more processors 814, one or more optional presentation components 816, one or more input/output (I/O) ports 818, one or more I/O components 820, and an illustrative power supply 822. The bus 810 represents what may be one or more busses (such as an address bus, data bus, or combination thereof). Although the various blocks of FIG. 8 are shown with lines for the sake of clarity, in reality, these blocks represent logical, not necessarily actual, components. For example, one may consider a presentation component such as a display device to be an I/O component. Also, processors have memory. It is appreciated that such is the nature of the art, and reiterate that the diagram of FIG. 8 is merely illustrative of an exemplary computing device that can be used in connection with one or more embodiments of the present invention. Distinction is not made between such categories as “workstation,” “server,” “laptop,” “hand-held device,” etc., as all are contemplated within the scope of FIG. 8 and reference to “computing device.”

The computing device 800 typically includes a variety of computer-readable media. Computer-readable media may be any available media that can be accessed by the computing device 800 and includes both volatile and nonvolatile media, removable and non-removable media implemented in any method or technology for storage of information such as computer-readable instructions, data structures, program modules or other data. Computer-readable media includes, but is not limited to, RAM, ROM, EEPROM, flash memory or other memory technology, CD-ROM, digital versatile disks (DVD) or other optical disk storage, magnetic cassettes, magnetic tape, magnetic disk storage or other magnetic storage devices, or any other medium which can be used to store the desired information and which can be accessed by the computing device 800. Combinations of any of the above are also included within the scope of computer-readable media.

The memory 812 includes computer-storage media in the form of volatile and/or nonvolatile memory. The memory may be removable, non-removable, or a combination thereof. Exemplary hardware devices include solid-state memory, hard drives, optical-disc drives, and the like. The computing device 800 includes one or more processors that read data from various entities such as the memory 812 or the I/O components 820. The optional presentation component(s) 816 present data indications to a user or other device. Exemplary presentation components include a display device, speaker, printing component, vibrating component, and the like.

The I/O ports 818 allow the computing device 800 to be logically coupled to other devices including the I/O components 820, some of which may be built in. Illustrative components include a microphone, joystick, game pad, satellite dish, scanner, printer, wireless device, and the like.

FIG. 9 depicts a flow diagram illustrating a method 900 for providing artificial lift to a well. At step 910, the method 900 includes identifying one or more parameters. In aspects, the one or more parameters can include any or all of the parameters discussed above with reference to the artificial lift processes and systems. For instance in one aspect, the one or more parameters can include one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. In aspects, the one or more parameters can be provided by or received from the one or more sensors 720 and/or the one or more data sources 760 discussed above with reference to the system 700 of FIG. 7.

At step 920, the method 900 includes determining a first flow rate of a liquid, a gas, or a liquid and gas mixture. In aspects, the step 920 can include determining a first flow rate of a liquid, a gas, or a liquid and gas mixture based on the one or more parameters identified in step 910. For instance, in such an aspect, the first flow rate of the liquid, gas, or liquid and gas mixture can be tailored based on the identifying of step 910 for injecting into a well to facilitate effective artificial lift. In the same or alternative aspects, the first flow rate of the liquid, gas, or liquid and gas mixture can be tailored based on the identifying of step 910 to facilitate downward gas bubble flow in the well. In aspects, determining a first flow rate of a liquid, a gas, or a liquid and gas mixture based on the one or more parameters identified in step 910 can include the use of the injection optimizer 710 discussed above with reference to the system 700 of FIG. 7.

FIG. 10 depicts a flow diagram illustrating a method 1000 for providing artificial lift to a well. At step 1010, the method 1000 includes identifying one or more parameters at a first time. In aspects, the one or more parameters can include any or all of the parameters discussed above with reference to the artificial lift processes and systems. For instance in one aspect, the one or more parameters can include one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters. In aspects, the one or more parameters can be provided by or received from the one or more sensors 720 and/or the one or more data sources 760 discussed above with reference to the system 700 of FIG. 7. For example, in one aspect, the step 1010 can include identifying one or more parameters that include identifying a first pressure of the liquid and gas mixture in a mixture conduit, a first outlet pressure of an artificial lift system, or a combination thereof.

At step 1020, the method 1000 includes determining a first flow rate of a liquid in a liquid and gas mixture. In aspects, the step 1020 can include determining a first flow rate of the liquid in the liquid and gas mixture based on the one or more parameters identified in step 1010. For instance, in such an aspect, the first flow rate of the liquid in a liquid and gas mixture can be tailored based on the identifying the one or more parameters of step 1010 to facilitate effective artificial lift. In the same or alternative aspects, the first flow rate of the liquid in a liquid and gas mixture can be tailored based on the identifying of step 1010 to facilitate downward gas bubble flow in the well. In aspects, determining a first flow rate of the liquid in a liquid and gas mixture based on the one or more parameters identified in step 1010 can include the use of the injection optimizer 710 discussed above with reference to the system 700 of FIG. 7.

At step 1030, the method 1000 can include identifying one or more parameters at a second time, e.g., at a second time that is subsequent to the first time. In the same or alternative aspects, the step 1030 can include identifying one or more parameters at a second time that is subsequent to injecting into a well the liquid and gas mixture at the first flow rate determined in step 1020. For example in certain aspects, the step 1030 can include identifying a second pressure of the liquid and gas mixture in the mixture conduit, a second outlet pressure of the artificial lift system, or a combination thereof.

At step 1040, the method can include determining that the second pressure of the liquid and gas mixture in the mixture conduit, the second outlet pressure, or a combination thereof is less than the first pressure of the liquid and gas mixture in the mixture conduit, the first outlet pressure, or the first combination thereof, respectively. For instance, the step 1040 includes determining that the pressure of the liquid and gas mixture in the mixture conduit, the outlet pressure, or a combination thereof has decreased subsequent to the steps 1010 and/or 1020. Stated differently, in various aspects, the step 1040 can include determining that after the liquid and gas mixture is injected into the well, it may be determined that the pressure of the liquid and gas mixture in the mixture conduit and/or the outlet pressure of the artificial lift system has decreased. As discussed herein, in aspects, this decrease in pressure of the liquid and gas mixture in the mixture conduit and/or the decrease in pressure of the artificial lift system outlet may signal that the injected gas has entered the production tubing in the case where the mixture was injected into the annulus, or that the injected gas has entered the annulus when the mixture was injected into the tubing.

At step 1050 of the method 1000, a second flow rate of the liquid in the liquid and gas mixture is determined. In aspects, the second flow rate of the liquid in the liquid and gas mixture can be determined based on the determination of the step 1040. In such an aspect, the second flow rate of the liquid may be decreased relative to the first liquid flow rate of the liquid. For instance, in certain aspects as discussed herein, it may be desirable to reduce the flow of the liquid in the mixture once the gas in the mixture has been determined to be entering the production tubing in the case where the mixture was injected into the annulus, or that the injected gas has entered the annulus when the mixture was injected into the tubing. In aspects, determining a second flow rate of the liquid in a liquid and gas mixture can include the use of the injection optimizer 710 discussed above with reference to the system 700 of FIG. 7.

FIG. 20 depicts a flow diagram illustrating a method 2000 for unloading a well. It should be understood that, in aspects, the artificial lift systems described herein can be utilized to perform all or a part of the method 2000. At step 2010, the method 2000 includes determining the optimum gas and liquid flow rates for the unloading operation. In aspects, the optimum gas and liquid flow rates can be determined using the injection optimizer 710 discussed above with reference to the system 700 of FIG. 7. Additionally or alternatively determining the optimum flow rates of the gas and the liquid can include using the determinations discussed below in Example 2.

At step 2020, the method 2000 includes initiating injection of the liquid into the well. In one aspect, the step 2020 can include injection of the liquid at a low rate e.g., at 5 gpm, and then slowly increasing to an optimum flow rate determined above, e.g., increase to an example optimum flow rate of 50 gpm with increments of 5 gpm per minute.

At step 2030, the method 2000 includes initiating gas injection, once the liquid injection reaches the optimum rate determined at step 2010. In aspects, the flow rate of the gas may be kept constant or substantially constant.

At step 2040, the method 2000 includes monitoring or identifying the injection pressure of the mixture. In aspects, the systems and processes described in detail above can be utilized to identify the injection pressure of the mixture. In aspects, as discussed above, a decrease in injection pressure can be utilized to determine that the gas and/or the mixture has entered the production tubing, e.g., via a deep-set valve.

At step 2050, the method 2000 includes identifying or determining that the gas and/or the mixture has reached the tubing outlet. In aspects, the systems and processes described in detail above can be utilized to identify that the gas and/or the mixture has reached the tubing outlet.

At step 2060, the method 2000 includes increasing the gas flow rate. In aspects, a specific increase in the gas flow rate can be determined utilizing the injection optimizer 710 discussed above with reference to the system 700 of FIG. 7. Additionally or alternatively, determining the increase in the gas flow rate can include using the determinations discussed below in Example 2.

At step 2070, the method 2000 includes maintaining the injection rates constant or substantially constant for at least the amount of time for the injection mixture to fully circulate the casing-tubing system. The amount of time can be determined using the superficial liquid and gas velocities to approximate the mixture velocity and to estimate the amount of time for the injection mixture to circulate from the casing inlet to tubing outlet. In aspects, the amount of time can be determined utilizing the injection optimizer 710 discussed above with reference to the system 700 of FIG. 7.

At step 2080, the method can include reducing the injection rate of the liquid. In aspects, the injection rate of the liquid can be reduced in this step 2080 while the gas rate remains substantially constant or constant. In one aspect, the duration, amount of, and rate of reduction of the liquid can be determined utilizing the injection optimizer 710 discussed above with reference to the system 700 of FIG. 7. Additionally or alternatively, determining the duration, the amount of, or rate of the reduction in the injection rate of the liquid can be accomplished using the determinations discussed below in Example 2. In aspects, the injection rate of the liquid can be decreased at a specified rate over a time period to a point where the liquid injection has ceased, and the gas injection rate remains substantially constant or constant. In such aspects, the gas injection is maintained until the well is unloaded. In aspects, one or more components of the system 700 of FIG. 7 can be utilized to determine when the well is unloaded.

EXAMPLE 1 Comparison of the Artificial Lift System Disclosed Herein to a Gas Lift Process

FIG. 11 depicts a pressure gradient chart showing the pressure of the liquid gradient in the tubing at the start of the kick-off process, labeled P_(wh). As used herein, the term “kick-off” refers to the point in time when a productive subsurface formation begins production and after the well has been unloaded of non-production fluid (e.g., water).

FIG. 11 shows the liquid gradient in the tubing at the start of the kick-off process, labeled P_(wh). The line labeled (P_(inj))_(G-L) in FIG. 11 is the gas gradient in the tubing-casing annulus required to initiate single-point gas lift. The curve labeled (P_(inj))_(LAGL) in FIG. 11 illustrates the lower surface injection pressure to kick-off gas injection at the injection point for the same well when utilizing the processes disclosed herein for injection of a mixture of a liquid and a gas.

FIG. 12 illustrates that the systems and processes described herein that utilize a mixture of a liquid and a gas can be achieved for a range of surface injection pressures. The liquid gradient in the tubing at the start of the kick-off process is labeled P_(wh). The line labeled (P_(inj))_(G-L) in FIG. 12 is the gas gradient in the tubing-casing annulus required to initiate single-point gas lift. The curves labeled (P_(inj))_(LAGL) in FIG. 12 illustrate that the systems and processes disclosed herein will be able to respond to periodic fluctuation in surface injection pressure, by tailoring the compositional makeup of the liquid and gas mixture to tailor the density to unload at various surface pressures.

FIG. 13 shows that for a given wellhead injection pressure there are a range of possible gradient curves as the liquid injection is varied in the processes and systems described herein. The liquid gradient in the tubing at the start of the kick-off process is labeled P_(wh). The line labeled (P_(inj))_(G-L) in FIG. 13 is the gas gradient in the tubing-casing annulus required to initiate single-point gas lift. The curves labeled (P_(inj))_(LAGL) in FIG. 13 above the optimal curve (middle or third curve from the left) will unload the well but inject more liquid than is necessary. The systems and processes disclosed herein will be able to interactively select the liquid injection rate to minimize liquid injection while also learning from the previous injection cycle how well the multiphase correlations for flow pattern and pressure drop functioned.

EXAMPLE 2 Simulation of Well Unloading Using Artificial Lift Processes Described Herein

Example 2 shows how the artificial lift processes described herein can be utilized for well unloading. Particularly, this Example 2 shows the simulation of a complete unloading process using artificial lift processes described herein.

The unloading simulation procedure utilized in this Example 2 is depicted in FIG. 16 in a series of gas/liquid fraction profiles of a simulated well at the beginning of the process and at the end of each of four unloading stages (e.g., different simulation times) for one case of a complete unloading simulation. The various stages of FIG. 16 are described below with a high-level description of the unloading procedure utilized in the simulation.

As can be seen in FIG. 16, the solid black represents the liquid phase fraction and the stipple pattern represents the gas phase fraction. The fractions are presented for the entire depth of the well for both the annulus (left-hand-side of each stage) and tubing (right-hand-side of each stage). The annulus and tubing are connected through a gas-lift valve (GLV) as shown in FIG. 16. As can be seen in FIG. 16, in the initial stage, the liquid fills the annulus and the tubing. In FIG. 16, stage 1 ends when injected fluids (gas and liquid) reach the bottom of the well and enter the tubing. At the beginning of stage 2, a small flow rate of gas is flowing in the tubing, while the water flow rate is kept constant and the gas flow rate is slowly increased, up to a point where the injection pressure reaches around 750 psig, which is considered the maximum available pressure for this Example 2. In this simulation, if a lower pressure is required, the main change should be to decrease the rate of increase of the gas rate over time. When the injection pressure reaches a value close to 750 psig, the gas flow rate is kept constant and stage 2 finishes. During stage 3, the gas flow rate is kept constant and the water flow rate is decreased. The reduction in the water flow rate is performed in small steps and the total volume of water in the well is closely monitored. Once the total liquid volume in the well reaches a level lower than the total tubing volume (88 ft³ in this Example 2), the water injection is shut off. At this point stage 4 starts and single-phase gas is injected in the annulus. The single-phase gas injection is maintained until the well is unloaded. Once the well is unloaded, the fluid injection stops and the simulations ends.

A more detailed step-by-step operational procedure utilized in this Example 2 will now be described. At step 1, before initiating the unloading operation, the optimum gas and liquid flow rates for stage 1 of the unloading operation are determined, in order to minimize the injection pressure. According to the American Petroleum Institute's Recommended Practices for Operation, Maintenance, Surveillance, and Troubleshooting of Gas-lift Installations (API RP 11V5 (2018)), the entirety of which is incorporated by reference herein, the liquid rate through the GLV should not exceed 1 bpm. FIG. 15 shows a graph of maximum injection pressure as a function of water flow rate for different gas injection rates using data from the experimental test well configuration depicted in FIG. 14A and simulation results using the simulation model depicted in FIG. 14B. Based on the data presented in FIG. 15, the initial gas and water flow rates to be applied to the complete unloading simulation of Example 2 are, respectively, 20 agpm and 50 gpm. In this Example 2, the actual flow rate of gas (20 agpm) is kept constant in this stage. However, as the injection pressure changes with time, the standard flow rate of gas also changes with time. The liquid used in this Example 2 is water, and it is assumed as an incompressible fluid. For this reason the actual and standard flow rates of the liquid are the same (for the water rates, gpm=agpm). The gas used in this Example 2 is compressed air.

At step 2, after determining the optimum gas and liquid flow rates from step 1, the liquid injection is initiated at 5 gpm, and increased to the optimum flow rate of 50 gpm with increments of 5 gpm per minute.

At step 3, once the liquid injection rate reaches the optimum flow rate from step 1, the gas injection is initiated. The actual flow rate for the gas injection, defined in step 1, should be kept constant in this Example 2.

At step 4, the injection pressure is monitored during stage 1. The injection pressure increases as the injected mixture gets deeper in the well.

At step 5, once the injected two-phase mixture reaches the GLV at the bottom of the well and the gas-liquid mixture enters the tubing, the injection pressure starts declining. This is the beginning of unloading stage 2. After this step, the outlet of the tubing is monitored for the presence of gas.

At step 6, once gas reaches the tubing outlet, the gas flow rate is increased (in small increments of around 0.25 agpm per minute) to reach a flow rate equal or higher than the minimal velocity of a gas required for the continuous removal of liquids from a well as calculated and described in Turner et al., Analysis and Prediction of Minimum Flow Rate for the Continuous Removal of Liquids from Gas Wells, Journal of Petroleum Technology, November, 1969, the entire contents of which are incorporated by reference herein, and in Coleman et al, A New Look at Prediction Gas-Well Load-Up, Journal of Petroleum Technology, March, 1991, pages 329-333, the entire contents of which are incorporated by reference herein.

At step 7, the injection rates constant for at least the amount of time for the injection mixture to fully circulate the casing-tubing system. The amount of time can be determined using the superficial liquid and gas velocities to approximate the mixture velocity and to estimate the amount of time for the injection mixture circulate from the casing inlet to tubing outlet.

At step 8, once the injection mixture has fully circulated through the casing-tubing system, stage 3 is initiated. During this stage the liquid injection is reduced by 1 gpm per quarter of the time needed to fully circulate the casing-tubing system, as calculated in step 7. In the scenario where the injection pressure starts to increase to values higher than the available injection pressure (750 gpm in the simulation model for this Example 2) the rate of reduction of the liquid injection is slowed down to less than 1 gpm per quarter of the time needed to fully circulate the casing-tubing system, as calculated in step 7.

At step 9, once the liquid flow rate reaches zero, stage 4 begins, and a constant gas injection is maintained until the well is fully unloaded.

FIGS. 17A-17C show the simulation results for a first complete unloading case. The simulation results presented in FIGS. 17A-17C have four unloading stages, and each stage is highlighted therein. Prior to the initiation of stage 1 (times between 0 to 140 sec), the well is full with liquid and single-phase liquid is injected in the annulus. The beginning of the unloading process (stage 1) occurs at time=140 seconds, when gas and liquid starts to be injected at a constant actual flow rate. This flow rate was kept constant between times 140 to 3,000 sec. At the end of stage 1, gas is already flowing upward in the tubing. FIG. 17A shows that during the stage 1 the injection pressure increased as the gas-liquid mixture (with lower density than the liquid previously in the annulus) reached a higher depth in the casing. When the injected gas-liquid mixture reached the bottom of the well, and started flowing upward in the tubing, the injection pressure started to decrease (near the end of stage 1).

During the stage 2 as noted above, the gas flow rate was increased with the objective of reducing the liquid fraction in the tubing. Without being bound by any particular theory, the injection pressure rose in the stage 2 as a consequence of increasing the gas flow rate to remove a higher amount of liquid out of the tubing. Without being bound by any particular theory, the increase in the injection pressure may be caused by a reduction in the density of the injected fluid and an increase of the fluid flow friction in the annulus, gas-lift valve, and/or tubing. In this stage, once the injection pressure reaches around 650 psig, the elevation in the injection pressure was ceased, which indicates the end of the stage 3, as seen in FIGS. 17A and 17B.

As FIG. 17C shows, at the end of the stage 2, more than 50% of the liquid volume initially in the well has been unloaded. As noted above, one objective of the stage 3 is to reduce the liquid volume in the well to a level close to the total volume of the tubing. To achieve the objective in stage 3, the liquid flow rate was reduced and the liquid volume in the well was monitored. As noted above, the liquid flow rate was reduced in small steps to avoid an abrupt change in the density of the injection mixture and, consequently, abrupt increase in the injection pressure. As soon as the total liquid volume in the system was smaller than the total tubing volume, stage 3 ended.

As stage 3 ended, the liquid volume in the system is considerably low (as can be seen in FIG. 17C) and stage 4 was initiated to finalize the well unloading. At the beginning of stage 4, the liquid injection was interrupted, and single-phase gas was injected in the well for a period of time long enough to remove all the remaining volume of liquid from the well. At the end of stage 4, the well was unloaded and, as can be seen in FIG. 17C, the total liquid volume in the system was zero.

Based on the simulation results for a first complete unloading case illustrated in FIGS. 17A-17C, it was observed that the maximum injection pressure was 691 psig. Unexpectedly, the simulation and data presented in this first unloading case, utilized about 42% lower gas injection pressure than the available pressure onsite (750 psig), which is the pressure required (750 psig) to perform a conventional gas-lift well unloading with conventional single-point injection in this model. It is also noted that while this simulation and data utilized water and air for the liquid and gas respectively, that the other liquids and gases discussed in detail above would achieve similar results in lowering the required gas pressure for unloading a well.

FIGS. 18A-18C show the simulation results for a second complete unloading case using the simulation and unloading operations described in Example 2. Further, FIGS. 19A-19C also show the simulation results for a third complete unloading case using the simulation and unloading operations described in Example 2. These second and third complete unloading simulations have the same characteristics of the result obtained first complete unloading case discussed in detail above. The complete unloading simulations and results of this Example 2 also showed that the simulation procedure described above is able to successful unload the experimental well evaluated in this Example 2.

Additional Embodiments

Embodiment 1. An artificial lift system, comprising: a first mixer; a gas conduit, the gas conduit extending between a gas intake at a first gas conduit end and the first mixer at a second gas conduit end; a liquid conduit, the liquid conduit extending between a liquid intake at a first liquid conduit end and the first mixer at a second liquid conduit end; a liquid pump, the liquid pump in fluid communication with the liquid conduit at a pump connection point between the first liquid intake and the first mixer; a frame assembly, the frame assembly comprising a base member, wherein each of the first mixer, the gas conduit, the liquid conduit, and the liquid pump are coupled to the base member; an outlet in fluid communication with the first mixer and adapted to output a first liquid and gas mixture into a well; and a computing device having at least one processor and computer-readable instructions stored thereon, the computer-readable instructions, when executed by the at least one processor cause the computing device to: identify one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, generate a first flow rate of the first liquid and gas mixture from the outlet and into the well.

Embodiment 2. The artificial lift system according to embodiment 1, wherein a liquid valve is coupled to the liquid conduit, wherein a gas valve is coupled to the gas conduit, and wherein the liquid valve and the gas valve are independently controlled by the computing device.

Embodiment 3. The artificial lift system according to embodiment 1 or 2, further comprising a variable frequency drive, the variable frequency drive operably coupled to the liquid pump.

Embodiment 4. The artificial lift system according to embodiment 3, wherein the variable frequency drive is controlled by the computing device.

Embodiment 5. The artificial lift system according to any of embodiments 1-4, wherein the computer-readable instructions further cause the computing device to adjust one or more of: a pressure or a flow rate of the liquid pump based on the identifying the one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.

Embodiment 6. The artificial lift system according to any of embodiments 1-5, further comprising: a chemical additive source and a second mixer, wherein the second mixer is in fluid communication with the chemical additive source, and wherein the second mixer is positioned between the first mixer and the outlet; and a chemical additive valve, the chemical additive valve coupled to the chemical additive source.

Embodiment 7. The artificial lift system according to embodiment 6, wherein the computer-readable instructions further cause the computing device to adjust a flow rate of one or more chemical additives from the chemical additive source based on the identifying the one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.

Embodiment 8. The artificial lift system according to any of embodiments 1-7, wherein the well geometry parameters comprise one or more of: an internal diameter of well tubing, an external diameter of well tubing, an internal diameter of a casing string, a depth of the casing string, an inclination of the casing string, a diameter of the vertical wellbore section, a depth of the vertical section, or a depth of an injection valve; wherein the produced fluids properties comprise one or more of: a density of the well-produced fluids, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, a viscosity of the well-produced fluids, a pressure of the well-produced fluids, a volume of the well-produced fluids, or a temperature of the well-produced fluids; wherein the well productivity parameters comprises one or more of: an average reservoir pressure, a flow potential for the well, production rates from the well, an average oil or condensate rate, an average water rate (barrels per day), an average gas rate, a flowing tubing pressure, a wellhead pressure, a choke setting, a well head flowing temperature; and wherein the surface production parameters comprise one or more of: a gas conduit pressure, a liquid conduit pressure, a liquid and gas mixture conduit pressure, an outlet pressure, a well head shut-in pressure, a well head shut-in temperature, a production line pressure, a separator pressure, a casing head shut-in temperature, a casing head shut-in pressure, the gas volume available or extractable from the gas source, or source gas pressure.

Embodiment 9. An artificial lift system, comprising: a first mixer in fluid communication with an outlet; a gas conduit, the gas conduit extending between a gas intake at a first gas conduit end and the first mixer at a second gas conduit end; a liquid conduit, the liquid conduit extending between a liquid intake at a first liquid conduit end and the first mixer at a second liquid conduit end; a liquid pump, the liquid pump in fluid communication with the liquid conduit at a pump connection point between the first liquid intake and the first mixer; a chemical additive source, the chemical additive source coupled to a second mixer, the second mixer in fluid communication with the chemical additive source at a chemical additive connection point that is positioned between the pump connection point and the outlet; a frame assembly, the frame assembly comprising a base member, wherein each of the first mixer, the gas conduit, the liquid conduit, the liquid pump, the chemical additive source, and the second mixer are coupled to the base member.

Embodiment 10. The artificial lift system according to embodiment 9, wherein the liquid pump comprises an electric motor.

Embodiment 11. The artificial lift system according to embodiment 9 or 10, further comprising a chemical additive valve, the chemical additive valve coupled to the chemical additive source.

Embodiment 12. The artificial lift system according to any of embodiments 9-11, wherein the frame assembly is adapted to transport the artificial lift assembly from the first well to a second well.

Embodiment 13. The artificial lift system according to embodiment 12, wherein the base member of the frame assembly has a length of at least about 3.5 meters and a width of at least about 1 meter.

Embodiment 14. The artificial lift system according to any of embodiments 9-13, wherein the outlet is in fluid communication with a wellhead of the first well.

Embodiment 15. The artificial lift system according to embodiment 14, wherein the first mixer comprises the first liquid and gas mixture, wherein the first liquid and gas mixture comprises liquid hydrocarbons.

Embodiment 16. The artificial lift system according to embodiment 14, wherein the liquid hydrocarbons comprise crude oil.

Embodiment 17. The artificial lift system according to embodiment 14, further comprising a well discharge meter coupled to the first well.

Embodiment 18. The artificial lift system according to any of embodiments 9-17, wherein the gas intake is coupled to a field gas supply on a pad site of the first well.

Embodiment 19. The artificial lift system according to any of embodiments 9-18, wherein the liquid intake is coupled to a field liquid supply on a pad site of the first well.

Embodiment 20. The artificial lift system according to any of embodiments 9-18, further comprising a housing coupled to the frame member, the housing having an interior volume, wherein each of the first mixer, the liquid conduit, the gas conduit, the chemical additive source, the second mixer, and the liquid pump are positioned in the interior volume of the housing.

Embodiment 21. A computing device having at least one processor and computer-readable instructions stored thereon, the computer-readable instructions, when executed by the at least one processor cause the computing device to: identify one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, determine a first flow rate of a liquid, a gas, or a liquid and gas mixture, for injecting into a well.

Embodiment 22. One or more nontransitory computer storage media storing computer-useable instructions that, when used by one or more computing devices, cause the one or more computing devices to perform operations comprising: identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, determining a first flow rate of a liquid, a gas, or a liquid and gas mixture, for injecting into a well.

Embodiment 23. A computing device having at least one processor and computer-readable instructions stored thereon, the computer-readable instructions, when executed by the at least one processor cause the computing device to: identify, at a first time, one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, wherein the identifying at the first time comprises identifying a first pressure of the liquid and gas mixture in a mixture conduit of an artificial lift system, a first outlet pressure of the artificial lift system, or a first combination thereof; based on the identifying at the first time, determine a first flow rate of a liquid in a liquid and gas mixture, for injecting into a well; identify, at a second time, one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, wherein the identifying at the second time comprises identifying a second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, a second outlet pressure of the artificial lift system, or a second combination thereof; determine that the second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, a second outlet pressure of the artificial lift system, or a second combination thereof is less than the first pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the first outlet pressure of the artificial lift system, or the first combination thereof, respectively; and determine a second flow rate of the liquid, wherein the second flow rate of the liquid is decreased relative to the first flow rate of the liquid, and wherein the second flow rate of the liquid is determined based on the determining that the second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the second outlet pressure of the artificial lift system, or the second combination thereof is less than the first pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the first outlet pressure of the artificial lift system, or the first combination thereof, respectively.

Embodiment 24. One or more nontransitory computer storage media storing computer-useable instructions that, when used by one or more computing devices, cause the one or more computing devices to perform operations comprising: identifying, at a first time, one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, wherein the identifying at the first time comprises identifying a first pressure of the liquid and gas mixture in a mixture conduit of an artificial lift system, a first outlet pressure of the artificial lift system, or a first combination thereof; based on the identifying at the first time, determining a first flow rate of a liquid in a liquid and gas mixture, for injecting into a well; identifying, at a second time, one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, wherein the identifying at the second time comprises identifying a second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, a second outlet pressure of the artificial lift system, or a second combination thereof; determining that the second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, a second outlet pressure of the artificial lift system, or a second combination thereof is less than the first pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the first outlet pressure of the artificial lift system, or the first combination thereof, respectively; and determining a second flow rate of the liquid, wherein the second flow rate of the liquid is decreased relative to the first flow rate of the liquid, and wherein the second flow rate of the liquid is determined based on the determining that the second pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the second outlet pressure of the artificial lift system, or the second combination thereof is less than the first pressure of the liquid and gas mixture in the mixture conduit of the artificial lift system, the first outlet pressure of the artificial lift system, or the first combination thereof, respectively.

Although the present invention has been described in terms of specific embodiments, it is not so limited. Suitable alterations/modifications for operation under specific conditions should be apparent to those skilled in the art. It is therefore intended that the following claims be interpreted as covering all such alterations/modifications as fall within the true spirit/scope of the invention. 

1. An artificial lift system, comprising: a first mixer; a gas conduit, the gas conduit extending between a gas intake at a first gas conduit end and the first mixer at a second gas conduit end; a liquid conduit, the liquid conduit extending between a liquid intake at a first liquid conduit end and the first mixer at a second liquid conduit end; a liquid pump, the liquid pump in fluid communication with the liquid conduit at a pump connection point between the first liquid intake and the first mixer; a frame assembly, the frame assembly comprising a base member, wherein each of the first mixer, the gas conduit, the liquid conduit, and the liquid pump are coupled to the base member; an outlet in fluid communication with the first mixer and adapted to output a first liquid and gas mixture into a well; and a computing device having at least one processor and computer-readable instructions stored thereon, the computer-readable instructions, when executed by the at least one processor cause the computing device to identify one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters; and based on the identifying one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters, generate a first flow rate of the first liquid and gas mixture from the outlet and into the well.
 2. The artificial lift system according to claim 1, wherein a liquid valve is coupled to the liquid conduit, wherein a gas valve is coupled to the gas conduit, and wherein the liquid valve and the gas valve are independently controlled by the computing device.
 3. The artificial lift system according to claim 1, further comprising a variable frequency drive, the variable frequency drive operably coupled to the liquid pump.
 4. The artificial lift system according to claim 3, wherein the variable frequency drive is controlled by the computing device.
 5. The artificial lift system according to claim 1, wherein the computer-readable instructions further cause the computing device to adjust one or more of: a pressure or a flow rate of the liquid pump based on the identifying the one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.
 6. The artificial lift system according to claim 1, further comprising: a chemical additive source and a second mixer, wherein the second mixer is in fluid communication with the chemical additive source, and wherein the second mixer is positioned between the first mixer and the outlet; and a chemical additive valve, the chemical additive valve coupled to the chemical additive source.
 7. The artificial lift system according to claim 6, wherein the computer-readable instructions further cause the computing device to adjust a flow rate of one or more chemical additives from the chemical additive source based on the identifying the one or more of: well geometry parameters, well productivity parameters, produced fluids properties, or surface production parameters.
 8. The artificial lift system according to claim 1, wherein the well geometry parameters comprise one or more of: an internal diameter of well tubing, an external diameter of well tubing, an internal diameter of a casing string, a depth of the casing string, an inclination of the casing string, a diameter of the vertical wellbore section, a depth of the vertical section, or a depth of an injection valve; wherein the produced fluids properties comprise one or more of: a density of the well-produced fluids, an API gravity of the produced fluids, such as an API gravity of the oil or condensate, a viscosity of the well-produced fluids, a pressure of the well-produced fluids, a volume of the well-produced fluids, or a temperature of the well-produced fluids; wherein the well productivity parameters comprises one or more of: an average reservoir pressure, a flow potential for the well, production rates from the well, an average oil or condensate rate, an average water rate (barrels per day), an average gas rate, a flowing tubing pressure, a wellhead pressure, a choke setting, a well head flowing temperature; and wherein the surface production parameters comprise one or more of: a gas conduit pressure, a liquid conduit pressure, a liquid and gas mixture conduit pressure, an outlet pressure, a well head shut-in pressure, a well head shut-in temperature, a production line pressure, a separator pressure, a casing head shut-in temperature, a casing head shut-in pressure, the gas volume available or extractable from the gas source, or source gas pressure.
 9. An artificial lift system, comprising: a first mixer in fluid communication with an outlet; a gas conduit, the gas conduit extending between a gas intake at a first gas conduit end and the first mixer at a second gas conduit end; a liquid conduit, the liquid conduit extending between a liquid intake at a first liquid conduit end and the first mixer at a second liquid conduit end; a liquid pump, the liquid pump in fluid communication with the liquid conduit at a pump connection point between the first liquid intake and the first mixer; a chemical additive source, the chemical additive source coupled to a second mixer, the second mixer in fluid communication with the chemical additive source at a chemical additive connection point that is positioned between the pump connection point and the outlet; a frame assembly, the frame assembly comprising a base member, wherein each of the first mixer, the gas conduit, the liquid conduit, the liquid pump, the chemical additive source, and the second mixer are coupled to the base member.
 10. The artificial lift system according to claim 9, wherein the liquid pump comprises an electric motor.
 11. The artificial lift system according to claim 9, further comprising a chemical additive valve, the chemical additive valve coupled to the chemical additive source.
 12. The artificial lift system according to claim 9, wherein the frame assembly is adapted to transport the artificial lift assembly from the first well to a second well.
 13. The artificial lift system according to claim 12, wherein the base member of the frame assembly has a length of at least about 3.5 meters and a width of at least about 1 meter.
 14. The artificial lift system according to claim 9, wherein the outlet is in fluid communication with a wellhead of the first well.
 15. The artificial lift system according to claim 14, wherein the first mixer comprises the first liquid and gas mixture, wherein the first liquid and gas mixture comprises liquid hydrocarbons.
 16. The artificial lift system according to claim 14, wherein the liquid hydrocarbons comprise crude oil.
 17. The artificial lift system according to claim 14, further comprising a well discharge meter coupled to the first well.
 18. The artificial lift system according to claim 9, wherein the gas intake is coupled to a field gas supply on a pad site of the first well.
 19. The artificial lift system according to claim 9, wherein the liquid intake is coupled to a field liquid supply on a pad site of the first well.
 20. The artificial lift system according to claim 9, further comprising a housing coupled to the frame member, the housing having an interior volume, wherein each of the first mixer, the liquid conduit, the gas conduit, the chemical additive source, the second mixer, and the liquid pump are positioned in the interior volume of the housing. 21-24. (canceled) 